U.S. patent application number 13/673123 was filed with the patent office on 2014-05-15 for methods of forming and placing proppant pillars into a subterranean formation.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Jeff Fleming, Feng Liang, Philip D. Nguyen, Christopher Parton, Jimmie D. Weaver.
Application Number | 20140131041 13/673123 |
Document ID | / |
Family ID | 50680562 |
Filed Date | 2014-05-15 |
United States Patent
Application |
20140131041 |
Kind Code |
A1 |
Liang; Feng ; et
al. |
May 15, 2014 |
Methods of Forming and Placing Proppant Pillars Into a Subterranean
Formation
Abstract
Methods of treating a subterranean formation comprising
providing a treatment fluid comprising a base fluid, proppant
particulates, a consolidating agent, a thermoplastic material, and
a degradable polyester material; placing the treatment fluid into
the subterranean formation; coating the proppant particulates and
the consolidating agent with the thermoplastic material and the
degradable polyester material together so as to form proppant
pillars; and degrading the degradable polyester material.
Inventors: |
Liang; Feng; (Houston,
TX) ; Nguyen; Philip D.; (Houston, TX) ;
Parton; Christopher; (Houston, TX) ; Fleming;
Jeff; (Duncan, OK) ; Weaver; Jimmie D.;
(Duncan, OK) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
50680562 |
Appl. No.: |
13/673123 |
Filed: |
November 9, 2012 |
Current U.S.
Class: |
166/280.2 |
Current CPC
Class: |
C09K 8/805 20130101 |
Class at
Publication: |
166/280.2 |
International
Class: |
C09K 8/80 20060101
C09K008/80; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method of treating a subterranean formation: providing a
treatment fluid comprising a base fluid, proppant particulates, a
consolidating agent, a thermoplastic material, and a degradable
polyester material; placing the treatment fluid into the
subterranean formation; coating the proppant particulates and the
consolidating agent with the thermoplastic material and the
degradable polyester material together so as to form proppant
pillars; and degrading the degradable polyester material.
2. The method of claim 1, wherein the thermoplastic material is
selected from the group consisting of a polyolefin; a
fluoropolymer; a polyimide; a polyamide; a polyurethane; a
polysulfone; a polycarbonate; a polyacrylate; a polyacrylonitrile;
a polyvinyl polymer; a cellulose; any derivatives thereof; any
copolymers thereof; and any combinations thereof.
3. The method of claim 1, wherein the degradable polyester material
is selected from the group consisting of an aliphatic polyester
homopolymer; an aliphatic polyester copolymer; a semi-aromatic
polyester copolymer; an aromatic copolymer; a telechelic polyester
oligomers; and any combinations thereof.
4. The method of claim 1, wherein the thermoplastic material is
present in an amount about from about 0.1% to about 20% by weight
of the proppant particulates.
5. The method of claim 1, wherein the degradable polyester material
is present in an amount about from about 0.01% to about 20% by
weight of the proppant particulates.
6. The method of claim 1, wherein treatment fluid further comprises
a degradable particulate.
7. The method of claim 6, wherein the degradable particulate is
present in an amount from about 5% to about 25% by weight of the
proppant particulates.
8. The method of claim 1, wherein the treatment fluid further
comprises a plasticizer selected from the group consisting of a
polyethylene glycol; a polyethylene oxide; an oligomeric lactic
acid; a citrate ester; a glucose monoester; a partially fatty acid
ester; a polyethylene monolaurate; a triacetin; a
poly(e-caprolactone); a poly(hydroxybutyrate); a
glycerin-1-benzoate-2,3-dilaurate; a
glycerin-2-benzoate-1,3-dilaurate; a bis(butyl diethylene
glycol)adipate; an ethylphthalylethyl glycolate; a glycerin
diacetate monocaprylate; a diacetyl monoacyl glycerol; a
polypropylene glycol; an epoxy derivative of a polypropylene
glycol; a poly(propylene glycol)dibenzoate; a dipropylene glycol
dibenzoate; a glycerol; an ethyl phthalyl ethyl glycolate; a
poly(ethylene adipate)distearate; a di-iso-butyl adipate; any
derivatives thereof; and any combinations thereof.
9. The method of claim 1, wherein the treatment fluid further
comprises an additive selected from the group consisting of
consisting of a salt; a weighting agent; an inert solid; a fluid
loss control agent; an emulsifier; a dispersion aid; a corrosion
inhibitor; an emulsion thinner; an emulsion thickener; a
viscosifying agent; a gelling agent; a crosslinking agent; a
breaker; a foaming agent; a gas; a surfactant; a lost circulation
material; a pH control additive; a biocide; a stabilizer; a
chelating agent; a scale inhibitor; a gas hydrate inhibitor; a
mutual solvent; an oxidizer; a reducer; a friction reducer; a clay
stabilizing agent; and any combination thereof.
10. A method of treating a subterranean formation: providing a
treatment fluid comprising a base fluid, proppant particulates, a
consolidating agent, and a degradable polyester material; placing
the treatment fluid into the subterranean formation; coating the
proppant particulates and the consolidating agent with the
degradable polyester material so as to form proppant pillars; and
degrading the degradable polyester material.
11. The method of claim 10, wherein the degradable polyester
material is selected from the group consisting of an aliphatic
polyester homopolymer; an aliphatic polyester copolymer; a
semi-aromatic polyester copolymer; an aromatic copolymer; a
telechelic polyester oligomers; and any combinations thereof.
12. The method of claim 10, wherein treatment fluid further
comprises a degradable particulate.
13. The method of claim 10, wherein the degradable polyester
material is present in an amount about from about 0.01% to about
20% by weight of the proppant particulate.
14. The method of claim 10, wherein the treatment fluid further
comprises a plasticizer selected from the group consisting of a
polyalkylene etherl a glyceryl monostearate; a tributyl citrate; an
octyl epoxy soyate; an epoxidized soybean oil; an epoxy tallate; an
epoxidized linseed oil; a polyhydroxyalkanoate; a glycol; any
derivatives thereof; and any combinations thereof.
15. A method of treating a subterranean formation having at least
one fracture comprising: providing a treatment fluid comprising a
base fluid, proppant particulates, a consolidating agent, and a
thermoplastic material; placing the treatment fluid into the
subterranean formation; and coating the proppant particulates and
consolidating agent with the thermoplastic material and the
degradable polyester material so as to form proppant pillars.
16. The method of claim 15, wherein the thermoplastic material is
selected from the group consisting of a polyolefin; a
fluoropolymer; a polyimide; a polyamide; a polyurethane; a
polysulfone; a polycarbonate; a polyacrylate; a polyacrylonitrile;
a polyvinyl polymer; a cellulose; any derivatives thereof; any
copolymers thereof; and any combinations thereof.
17. The method of claim 15, wherein treatment fluid further
comprises a degradable particulates.
18. The method of claim 15, wherein the thermoplastic material is
present in an amount about from about 0.1% to about 20% by weight
of the proppant particulate.
19. The method of claim 15, wherein treatment fluid further
comprises a degradable particulate.
20. The method of claim 19, wherein the degradable particulate is
present in an amount from about 5% to about 25% by weight of the
proppant particulate.
Description
BACKGROUND
[0001] The present invention relates to methods of forming and
placing proppant pillars into a subterranean formation.
[0002] Subterranean wells (e.g., hydrocarbon producing wells, water
producing wells, or injection wells) are often stimulated by
hydraulic fracturing treatments. In traditional hydraulic
fracturing treatments, a treatment fluid, which may also function
simultaneously or subsequently as a carrier fluid, is pumped into a
portion of a subterranean formation at a rate and pressure
sufficient to break down the formation and create one or more
fractures therein. Typically, particulate solids, such as graded
sand, are suspended in a portion of the treatment fluid and then
deposited into the fractures. These particulate solids, or
"proppant particulates," serve to prevent the fractures from fully
closing once the hydraulic pressure is removed. By keeping the
fractures from fully closing, the proppant particulates aid in
forming conductive paths through which fluids produced from the
formation may flow.
[0003] The degree of success of a fracturing operation depends, at
least in part, upon fracture porosity and conductivity once the
fracturing operation is complete and production is begun.
Traditional fracturing operations place a large volume of proppant
particulates into a fracture to form a "proppant pack" in order to
ensure that the fracture does not close completely upon removing
the hydraulic pressure. The ability of proppant particulates to
maintain a fracture open depends upon the ability of the proppant
particulates to withstand fracture closure and, therefore, is
typically proportional to the volume of proppant particulates
placed in the fracture. The porosity of a proppant pack within a
fracture is related to the interconnected interstitial spaces
between abutting proppant particulates. Thus, the fracture porosity
is closely related to the strength of the placed proppant
particulates and often tight proppant packs are unable to produce
highly conductive channels within a fracture, while reducing the
volume of the proppant particulates is unable to withstand fracture
closures.
[0004] One way proposed to combat the problems inherent in tight
proppant packs involves the use of proppant pillars. As used
herein, the term "proppant pillar" refers to a coherent body of
consolidated proppant particulates that generally remain a coherent
body and do not disperse into smaller bodies without the
application of shear. Proppant pillars are comprised of a plurality
of proppant particulates formed into a tight cluster and are
capable of withstanding fracture closure pressures. The use of
proppant pillars, therefore, may reduce or eliminate the likelihood
of partial or complete fracture closure. The proppant pillars
placed into a fracture do not abut together perfectly and therefore
may achieve infinite conductivity channels (e.g., unobstructed
pathways) for produced fluid flow. However, while proppant pillars
can overcome the issues associated with tight proppant packs, in
practice several issues may prevent their optimal performance.
Specifically, while proppant pillars do not disperse into smaller
bodies in the absence of shear, they often encounter shear when
being placed into a subterranean formation, particularly when
encountering fracture closure stresses. Thus, the proppant pillars
may be of a sub-optimal size due to dispersion after fracture
closure, such that they are unable to maintain fracture
conductivity. Therefore, a method of forming and placing proppant
pillars into a subterranean formation such that they do not
disperse into smaller bodies may be of benefit to one of ordinary
skill in the art.
SUMMARY OF THE INVENTION
[0005] The present invention relates to methods of forming and
placing proppant pillars into a subterranean formation.
[0006] In some embodiments, the present invention provides a method
of treating a subterranean formation comprising providing a
treatment fluid comprising a base fluid, proppant particulates, a
consolidating agent, a thermoplastic material, and a degradable
polyester material; placing the treatment fluid into the
subterranean formation; coating the proppant particulates and the
consolidating agent with the thermoplastic material and the
degradable polyester material together so as to form proppant
pillars; and degrading the degradable polyester material.
[0007] In other embodiments, the present invention provides a
method of treating a subterranean formation: providing a treatment
fluid comprising a base fluid, proppant particulates, a
consolidating agent, and a degradable polyester material; placing
the treatment fluid into the subterranean formation; coating the
proppant particulates and the consolidating agent with the
degradable polyester material so as to form proppant pillars; and
degrading the degradable polyester material.
[0008] In still other embodiments, the present invention provides a
method of treating a subterranean formation having at least one
fracture comprising: providing a treatment fluid comprising a base
fluid, proppant particulates, a consolidating agent, and a
thermoplastic material; placing the treatment fluid into the
subterranean formation; and coating the proppant particulates and
consolidating agent with the thermoplastic material and the
degradable polyester material so as to form proppant pillars.
[0009] The features and advantages of the present invention will be
readily apparent to those skilled in the art upon a reading of the
description of the preferred embodiments that follows.
DETAILED DESCRIPTION
[0010] The present invention relates to methods of forming and
placing proppant pillars into a subterranean formation.
[0011] The present invention provides methods of creating highly
conductive channels in propped fractures using proppant pillars
that remain a coherent body when exposed to most shear stresses
within a subterranean formation. Specifically, the present
invention provides methods of forming proppant pillars by adhering
a thermoplastic material and/or a degradable polyester material
onto proppant particulates with the use of a consolidating agent so
as to form a proppant pillar stronger than traditional proppant
pillars and, thus, able to withstand high fracture closure
stresses. The proppant pillars are preferably formed in situ. In
situ coating may allow the proppant pillars to conform to the shape
and size of the fracture. The methods of the present invention may
be utilized in vertical and horizontal drilled wells and in main
wellbores or lateral wellbores.
[0012] In one embodiment, the present invention provides a method
of treating a subterranean formation comprising providing a
treatment fluid comprising a base fluid, proppant particulates, a
consolidating agent, a thermoplastic material, and a degradable
polyester material. The treatment fluid is introduced into the
subterranean formation and the thermoplastic and degradable
polyester material together adhere the proppant particulates by the
consolidating agent so as to form proppant pillars. The degradable
polyester material is then degraded. In other embodiments, the
proppant pillars may be adhered to either the thermoplastic
material alone or the degradable polyester material alone.
[0013] Any base fluid suitable for use in a stimulation or well
operation may be used in the treatment fluid of the present
invention. Suitable base fluids for use in conjunction with the
present invention may include, but are not limited to, oil-based
fluids, aqueous-based fluids, aqueous-miscible fluids, water-in-oil
emulsions, or oil-in-water emulsions. Suitable oil-based fluids may
include alkanes; olefins; aromatic organic compounds; cyclic
alkanes; paraffins; diesel fluids; mineral oils; desulfurized
hydrogenated kerosenes; and any combination thereof. Suitable
aqueous-based fluids may include fresh water; saltwater (e.g.,
water containing one or more salts dissolved therein); brine (e.g.,
saturated salt water), seawater; and any combination thereof.
Generally, the water may be from any source (e.g., produced aqueous
fluids), provided that it does not contain components that
adversely affect the stability and/or performance of the treatment
fluid of the present invention. Suitable aqueous-miscible fluids
may include, but are not limited to, alcohols; (e.g., methanol,
ethanol, n-propanol, isopropanol, n-butanol, sec-butanol,
isobutanol, and t-butanol); glycerins; glycols (e.g., polyglycols,
propylene glycol, and ethylene glycol); polyglycol amines; polyols;
any derivative thereof; any in combination with salts (e.g., sodium
chloride, calcium chloride, calcium bromide, zinc bromide,
potassium carbonate, sodium formate, potassium formate, cesium
formate, sodium acetate, potassium acetate, calcium acetate,
ammonium acetate, ammonium chloride, ammonium bromide, sodium
nitrate, potassium nitrate, ammonium nitrate, ammonium sulfate,
calcium nitrate, sodium carbonate, and potassium carbonate); any in
combination with an aqueous-based fluid; and any combinations
thereof. Suitable water-in-oil emulsions, also known as invert
emulsions, may have an oil-to-water ratio from a lower limit of
greater than about 50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or
80:20 to an upper limit of less than about 100:0, 95:5, 90:10,
85:15, 80:20, 75:25, 70:30, or 65:35 by volume in the base fluid,
where the amount may range from any lower limit to any upper limit
and encompass any subset therebetween. Examples of suitable invert
emulsions include those disclosed in U.S. Pat. No. 5,905,061
entitled "Invert Emulsion Fluids Suitable for Drilling" filed on
May 23, 1997, U.S. Pat. No. 5,977,031 entitled "Ester Based Invert
Emulsion Drilling Fluids and Muds Having Negative Alkalinity" filed
on Aug. 8, 1998, U.S. Pat. No. 6,828,279 entitled "Biodegradable
Surfactant for Invert Emulsion Drilling Fluid" filed on Aug. 10,
2001, U.S. Pat. No. 7,534,745 entitled "Gelled Invert Emulsion
Compositions Comprising Polyvalent Metal Salts of an
Organophosphonic Acid Ester or an Organophosphinic Acid and Methods
of Use and Manufacture" filed on May 5, 2004, U.S. Pat. No.
7,645,723 entitled "Method of Drilling Using Invert Emulsion
Drilling Fluids" filed on Aug. 15, 2007, and U.S. Pat. No.
7,696,131 entitled "Diesel Oil-Based Invert Emulsion Drilling
Fluids and Methods of Drilling Boreholes" filed on Jul. 5, 2007,
each of which are incorporated herein by reference in their
entirety. It should be noted that for water-in-oil and oil-in-water
emulsions, any mixture of the above may be used including the water
being and/or comprising an aqueous-miscible fluid.
[0014] The base fluids for use in the treatment fluids of the
present invention may additionally be foamed or gelled. As used
herein, the term "foam" refers to a two-phase composition having a
continuous liquid phase and a discontinuous gas phase. In some
embodiments, treatment fluids for use in conjunction with the
present invention may comprise a base fluid, a gas, and a foaming
agent.
[0015] Suitable gases for use in conjunction with the present
invention may include, but are not limited to, nitrogen; carbon
dioxide; air; methane; helium; argon; and any combinations thereof.
One skilled in the art, with the benefit of this disclosure, will
recognize the benefit of each gas. By way of nonlimiting example,
carbon dioxide foams may have deeper well capability than nitrogen
foams because carbon dioxide emulsions have greater density than
nitrogen gas foams so that the surface pumping pressure required to
reach a corresponding depth is lower with carbon dioxide than with
nitrogen. Moreover, the higher density may impart greater
particulate or proppant transport capability, if necessary, up to
about 12 lb of proppant per gallon of fracture fluid.
[0016] In some embodiments, the quality of the foamed treatment
fluid may range from a lower limit of about 5%, 10%, 25%, 40%, 50%,
60%, or 70% gas volume to an upper limit of about 95%, 90%, 80%,
75%, 60%, or 50% gas volume, and wherein the quality of the foamed
treatment fluid may range from any lower limit to any upper limit
and encompass any subset therebetween. Most preferably, the foamed
treatment fluid may have a foam quality from about 85% to about
95%, or about 90% to about 95%.
[0017] Suitable foaming agents for use in conjunction with the
present invention may include, but are not limited to, cationic
foaming agents, anionic foaming agents, amphoteric foaming agents,
nonionic foaming agents, or any combination thereof. Nonlimiting
examples of suitable foaming agents may include, but are not
limited to, surfactants like betaines; sulfated or sulfonated
alkoxylates; alkyl quarternary amines; alkoxylated linear alcohols;
alkyl sulfonates; alkyl aryl sulfonates; C10-C20 alkyldiphenyl
ether sulfonates; polyethylene glycols; ethers of alkylated phenol;
sodium dodecylsulfate; alpha olefin sulfonates (e.g., sodium
dodecane sulfonate, trimethyl hexadecyl ammonium bromide, and the
like); any derivatives thereof; or any combinations thereof.
Foaming agents may be included in foamed treatment fluids at
concentrations ranging typically from about 0.05% to about 2% of
the liquid component by weight (e.g., from about 0.5 to about 20
gallons per 1000 gallons of liquid).
[0018] In some embodiments, the treatment fluids of the present
invention may comprise a base fluid, a gelling agent, a
crosslinking agent, and/or a gel breaker. The gelling agents
suitable for use in the present invention may comprise any
substance (e.g., a polymeric material) capable of increasing the
viscosity of the treatment fluid. In certain embodiments, the
gelling agent may comprise one or more polymers that have at least
two molecules that are capable of forming a crosslink in a
crosslinking reaction in the presence of a crosslinking agent,
and/or polymers that have at least two molecules that are so
crosslinked (i.e., a crosslinked gelling agent). The gelling agents
may be naturally-occurring gelling agents, synthetic gelling
agents, or a combination thereof. The gelling agents also may be
cationic gelling agents, anionic gelling agents, or a combination
thereof. Suitable gelling agents include, but are not limited to,
polysaccharides, biopolymers, and/or derivatives thereof that
contain one or more of these monosaccharide units: galactose;
mannose; glucoside; glucose; xylose; arabinose; fructose;
glucuronic acid; or pyranosyl sulfate. Examples of suitable
polysaccharides include, but are not limited to, guar gums (e.g.,
hydroxyethyl guar, hydroxypropyl guar, carboxymethyl guar,
carboxymethylhydroxyethyl guar, and carboxymethylhydroxypropyl guar
("CMHPG")); cellulose derivatives (e.g., hydroxyethyl cellulose,
carboxyethylcellulose, carboxymethylcellulose, and
carboxymethylhydroxyethylcellulose); xanthan; scleroglucan;
succinoglycan; diutan; and any combinations thereof. In certain
embodiments, the gelling agents comprise an organic carboxylated
polymer, such as CMHPG.
[0019] Suitable synthetic polymers include, but are not limited to,
2,2'-azobis(2,4-dimethyl valeronitrile);
2,2'-azobis(2,4-dimethyl-4-methoxy valeronitrile); polymers and
copolymers of acrylamide ethyltrimethyl ammonium chloride;
acrylamide; acrylamido- and methacrylamido-alkyl trialkyl ammonium
salts; acrylamidomethylpropane sulfonic acid; acrylamidopropyl
trimethyl ammonium chloride; acrylic acid; dimethylaminoethyl
methacrylamide; dimethylaminoethyl methacrylate;
dimethylaminopropyl methacrylamide; dimethyldiallylammonium
chloride; dimethylethyl acrylate; fumaramide; methacrylamide;
methacrylamidopropyl trimethyl ammonium chloride;
methacrylamidopropyldimethyl-n-dodecylammonium chloride;
methacrylamidopropyldimethyl-n-octylammonium chloride;
methacrylamidopropyltrimethylammonium chloride; methacryloylalkyl
trialkyl ammonium salts; methacryloylethyl trimethyl ammonium
chloride; methacrylylamidopropyldimethylcetylammonium chloride;
N-(3-sulfopropyl)-N-methacrylamidopropyl-N,N-dimethyl ammonium
betaine; N,N-dimethylacrylamide; N-methylacrylamide;
nonylphenoxypoly(ethyleneoxy)ethylmethacrylate; partially
hydrolyzed polyacrylamide; poly 2-amino-2-methyl propane sulfonic
acid; polyvinyl alcohol; sodium 2-acrylamido-2-methylpropane
sulfonate; quaternized dimethylaminoethylacrylate; quaternized
dimethylaminoethylmethacrylate; any derivatives thereof; and any
combinations thereof. In certain embodiments, the gelling agent
comprises an acrylamide/2-(methacryloyloxy)ethyltrimethylammonium
methyl sulfate copolymer. In certain embodiments, the gelling agent
may comprise an
acrylamide/2-(methacryloyloxy)ethyltrimethylammonium chloride
copolymer. In certain embodiments, the gelling agent may comprise a
derivatized cellulose that comprises cellulose grafted with an
allyl or a vinyl monomer, such as those disclosed in U.S. Pat. Nos.
4,982,793, 5,067,565, and 5,122,549, the entire disclosures of
which are incorporated herein by reference.
[0020] Additionally, polymers and copolymers that comprise one or
more functional groups (e.g., hydroxyl, cis-hydroxyl, carboxylic
acids, derivatives of carboxylic acids, sulfate, sulfonate,
phosphate, phosphonate, amino, or amide groups) may be used as
gelling agents.
[0021] The gelling agent may be present in the breakable gel fluids
useful in the methods of the present invention in an amount
sufficient to provide the desired viscosity. In some embodiments,
the gelling agents (i.e., the polymeric material) may be present in
an amount in the range of from about 0.1% to about 10% by weight of
the treatment fluid. In certain embodiments, the gelling agents may
be present in an amount in the range of from about 0.15% to about
2.5% by weight of the treatment fluid.
[0022] In those embodiments of the present invention where it is
desirable to crosslink the gelling agent, the breakable gel fluid
may comprise one or more crosslinking agents. The crosslinking
agents may comprise a borate ion, a metal ion, or similar component
that is capable of crosslinking at least two molecules of the
gelling agent. Examples of suitable crosslinking agents include,
but are not limited to, borate ions; magnesium ions; zirconium IV
ions; titanium IV ions; aluminum ions; antimony ions; chromium
ions; iron ions; copper ions; magnesium ions; and zinc ions. These
ions may be provided by providing any compound that is capable of
producing one or more of these ions. Examples of such compounds
include, but are not limited to, ferric chloride; boric acid;
disodium octaborate tetrahydrate; sodium diborate; pentaborates;
ulexite; colemanite; magnesium oxide; zirconium lactate; zirconium
triethanol amine; zirconium lactate triethanolamine; zirconium
carbonate; zirconium acetylacetonate; zirconium malate; zirconium
citrate; zirconium diisopropylamine lactate; zirconium glycolate;
zirconium triethanol amine glycolate; zirconium lactate glycolate;
titanium lactate; titanium malate; titanium citrate; titanium
ammonium lactate; titanium triethanolamine; titanium
acetylacetonate; aluminum lactate; aluminum citrate; antimony
compounds; chromium compounds; iron compounds; copper compounds;
zinc compounds; and combinations thereof. In certain embodiments of
the present invention, the crosslinking agent may be formulated to
remain inactive until it is "activated" by, among other things,
certain conditions in the fluid (e.g., pH, temperature, etc.)
and/or interaction with some other substance. In some embodiments,
the activation of the crosslinking agent may be delayed by
encapsulation with a coating (e.g., a porous coating through which
the crosslinking agent may diffuse slowly, or a degradable coating
that degrades downhole) that delays the release of the crosslinking
agent until a desired time or place. The choice of a particular
crosslinking agent will be governed by several considerations that
will be recognized by one skilled in the art, including but not
limited to the type of gelling agent included, the molecular weight
of the gelling agent(s), the conditions in the subterranean
formation being treated, the safety handling requirements, the pH
of the treatment fluid, temperature, and/or the desired delay for
the crosslinking agent to crosslink the gelling agent
molecules.
[0023] When included, suitable crosslinking agents may be present
in the breakable gel fluids useful in the methods of the present
invention in an amount sufficient to provide the desired degree of
crosslinking between molecules of the gelling agent. In certain
embodiments, the crosslinking agent may be present in the breakable
gel fluids of the present invention in an amount in the range of
from about 0.005% to about 1% by weight of the treatment fluid. In
certain embodiments, the crosslinking agent may be present in the
breakable gel fluids of the present invention in an amount in the
range of from about 0.05% to about 1% by weight of the treatment
fluid. One of ordinary skill in the art, with the benefit of this
disclosure, will recognize the appropriate amount of crosslinking
agent to include in a breakable gel fluid of the present invention
based on, among other things, the temperature conditions of a
particular application, the type of gelling agents used, the
molecular weight of the gelling agents, the desired degree of
viscosification, and/or the pH of the breakable gel fluid.
[0024] The treatment fluids useful in the methods of the present
invention also may include internal gel breakers such as enzyme,
oxidizing, acid buffer, or delayed gel breakers. The gel breakers
may cause the breakable gel fluids of the present invention to
revert to thin fluids that can be produced back to the surface. In
some embodiments, the gel breaker may be formulated to remain
inactive until it is "activated" by, among other things, certain
conditions in the fluid (e.g. pH, temperature, etc.) and/or
interaction with some other substance. In some embodiments, the gel
breaker may be delayed by encapsulation with a coating (e.g., a
porous coatings through which the breaker may diffuse slowly, or a
degradable coating that degrades downhole) that delays the release
of the gel breaker. In other embodiments the gel breaker may be a
degradable material (e.g., polylactic acid or polygylcolic acid)
that releases an acid or alcohol in the presence of an aqueous
liquid. In certain embodiments, the gel breaker used may be present
in the treatment fluids in an amount in the range of from about
0.0001% to about 200% by weight of the gelling agent. One of
ordinary skill in the art, with the benefit of this disclosure,
will recognize the type and amount of a gel breaker to include in
the breakable gel fluids of the present invention based on, among
other factors, the desired amount of delay time before the gel
breaks, the type of gelling agents used, the temperature conditions
of a particular application, the desired rate and degree of
viscosity reduction, and/or the pH of the treatment fluid.
[0025] The base fluids for use in the treatment fluids of the
present invention may comprise an additive selected from the group
consisting of a salt; a weighting agent; an inert solid; a fluid
loss control agent; an emulsifier; a dispersion aid; a corrosion
inhibitor; an emulsion thinner; an emulsion thickener; a
viscosifying agent; a gelling agent; a crosslinking agent; a
breaker; a foaming agent; a gas; a surfactant; a lost circulation
material; a pH control additive; a biocide; a stabilizer; a
chelating agent; a scale inhibitor; a gas hydrate inhibitor; a
mutual solvent; an oxidizer; a reducer; a friction reducer; a clay
stabilizing agent; and any combination thereof.
[0026] In some embodiments, the base fluid of the present invention
and any additives may be used as a spacer fluid, such that the
treatment fluids of the present invention are introduced into a
subterranean formation intermittently between the spacer fluid.
This may allow the proppant pillars to be placed in a more spaced
fashion that without the use of the spacer fluid. One of ordinary
skill in the art will recognize whether a spacer fluid should be
used in a particular application of the methods disclosed
herein.
[0027] Proppant particulates suitable for use in the methods of the
present invention may be of any size and shape combination known in
the art as suitable for use in a subterranean operation. Generally,
where the chosen proppant is substantially spherical, suitable
proppant particulates have a size in the range of from about 2 to
about 400 mesh, U.S. Sieve Series. In some embodiments of the
present invention, the proppant particulates have a size in the
range of from about 8 to about 120 mesh, U.S. Sieve Series. A major
advantage of using this method is there is no need for the proppant
particulates to be sieved or screened to a particular or specific
particle mesh size or particular particle size distribution, but
rather a wide or broad particle size distribution can be used.
[0028] In some embodiments of the present invention it may be
desirable to use substantially non-spherical proppant particulates.
Suitable substantially non-spherical proppant particulates may be
cubic, polygonal, fibrous, or any other non-spherical shape. Such
substantially non-spherical proppant particulates may be, for
example, cubic-shaped, rectangular-shaped, rod-shaped,
ellipse-shaped, cone-shaped, pyramid-shaped, or cylinder-shaped.
That is, in embodiments wherein the proppant particulates are
substantially non-spherical, the aspect ratio of the material may
range such that the material is fibrous to such that it is cubic,
octagonal, or any other configuration. Substantially non-spherical
proppant particulates are generally sized such that the longest
axis is from about 0.02 inches to about 0.3 inches in length. In
other embodiments, the longest axis is from about 0.05 inches to
about 0.2 inches in length. In one embodiment, the substantially
non-spherical proppant particulates are cylindrical having an
aspect ratio of about 1.5 to 1 and about 0.08 inches in diameter
and about 0.12 inches in length. In another embodiment, the
substantially non-spherical proppant particulates are cubic having
sides about 0.08 inches in length.
[0029] Proppant particulates suitable for use in the present
invention may comprise any material suitable for use in
subterranean operations. Suitable materials for these proppant
particulates include, but are not limited to, sand; bauxite;
ceramic materials; glass materials; polymer materials (such as
ethylene-vinyl acetate or composite materials);
polytetrafluoroethylene materials; nut shell pieces; cured resinous
particulates comprising nut shell pieces; seed shell pieces; cured
resinous particulates comprising seed shell pieces; fruit pit
pieces; cured resinous particulates comprising fruit pit pieces;
wood, composite particulates; and combinations thereof. Suitable
composite particulates may comprise a binder and a filler material
wherein suitable filler materials include silica; alumina; fumed
carbon; carbon black; graphite; mica; titanium dioxide; barite;
meta-silicate; calcium silicate; kaolin; talc; zirconia; boron; fly
ash; hollow glass microspheres; solid glass; and combinations
thereof. Suitable proppant particles for use in conjunction with
the present invention may be any known shape of material, including
substantially spherical materials; fibrous materials; polygonal
materials (such as cubic materials); and combinations thereof.
[0030] The proppant particulates are included in the treatment
fluids of the present invention with a consolidating agent. The
consolidating agent of the present invention is used to adhere the
thermoplastic material and/or degradable polyester material of the
present invention to the proppant particulates. Upon reaching
certain temperatures, the thermoplastic material and/or the
degradable polyester material may become pliable and twist and
change conformation so as to coat the proppant particulates adhered
thereto by aid of the consolidating agent. The consolidating agent
may additionally aid in binding various proppant particulates
together to aid in forming proppant pillars. Any consolidating
agent suitable for use in subterranean operations and capable of
binding proppant particulates together such that the individual
proppant particulates do not generally disperse without the
presence of shear may be used in the methods of the present
invention. Suitable consolidating agents may include, but are not
limited to, non-aqueous tackifying agents; aqueous tackifying
agents; emulsified tackifying agents; silyl-modified polyamide
compounds; resins; crosslinkable aqueous polymer compositions;
polymerizable organic monomer compositions; consolidating agent
emulsions; zeta-potential modifying aggregating compositions;
silicon-based resins; and binders. Combinations and/or derivatives
of these also may be suitable. Nonlimiting examples of suitable
non-aqueous tackifying agents may be found in U.S. Pat. Nos.
7,392,847, 7,350,579, 5,853,048; 5,839,510; and 5,833,000, the
entire disclosures of which are herein incorporated by reference.
Nonlimiting examples of suitable aqueous tackifying agents may be
found in U.S. Pat. Nos. 8,076,271, 7,131,491, 5,249,627 and
4,670,501, the entire disclosures of which are herein incorporated
by reference. Nonlimiting examples of suitable crosslinkable
aqueous polymer compositions may be found in U.S. Patent
Application Publication Nos. 2010/0160187 (pending) and U.S. Pat.
No. 8,136,595 the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
silyl-modified polyamide compounds may be found in U.S. Pat. No.
6,439,309 entitled the entire disclosure of which is herein
incorporated by reference. Nonlimiting examples of suitable resins
may be found in U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426;
6,582,819; 6,311,773; and 4,585,064 as well as U.S. Patent
Application Publication No. and 2008/0006405 (abandoned) and U.S.
Pat. No. 8,261,833, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
polymerizable organic monomer compositions may be found in U.S.
Pat. No. 7,819,192, the entire disclosure of which is herein
incorporated by reference. Nonlimiting examples of suitable
consolidating agent emulsions may be found in U.S. Patent
Application Publication No. 2007/0289781 (pending) the entire
disclosure of which is herein incorporated by reference.
Nonlimiting examples of suitable zeta-potential modifying
aggregating compositions may be found in U.S. Pat. Nos. 7,956,017
and 7,392,847, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable
silicon-based resins may be found in Application Publication Nos.
2011/0098394 (pending), 2010/0179281 (pending), and U.S. Pat. Nos.
8,168,739 and 8,261,833, the entire disclosures of which are herein
incorporated by reference. Nonlimiting examples of suitable binders
may be found in U.S. Pat. Nos. 8,003,579; 7,825,074; and 6,287,639,
as well as U.S. Patent Application Publication No. 2011/0039737,
the entire disclosures of which are herein incorporated by
reference. It is within the ability of one skilled in the art, with
the benefit of this disclosure, to determine the type and amount of
consolidating agent to include in the methods of the present
invention to achieve the desired results. The consolidating agent
may be present in the treatment fluids of the present invention in
an about from about 1% to about 5% by weight of the proppant
particulate. In preferred embodiments, the consolidating agent may
be present in the treatment fluids of the present invention from
about 0.5% to about 10% by weight of the proppant particulate.
[0031] In some embodiments of the present invention, degradable
particulates may be included in the treatment fluids such that they
form a portion of the proppant pillar. Upon a triggering event, the
degradable particulates may be degraded, leaving behind spaces in
the proppant pillar that may enhance the conductivity of the
propped fracture. It may desirable that the degradable particulate
has similar particle size, shape, and specific gravity as those of
the proppant particulates.
[0032] Suitable degradable particulates include oil-degradable
polymers. Where such oil-degradable polymers are used, the
oil-degradable polymers may be degraded by the produced fluids.
Oil-degradable polymers that may be used in accordance with the
present invention may be either natural or synthetic polymers. Some
particular examples include, but are not limited to, polyacrylics;
polyamides; and polyolefins such as polyethylene, polypropylene,
polyisobutylene, and polystyrene. Other suitable oil-degradable
polymers include those that have a melting point that is such that
the oil-degradable polymer will melt or dissolve at the temperature
of the subterranean formation in which it is placed such as a wax
material.
[0033] In addition to oil-degradable polymers, other degradable
particulates that may be used in conjunction with the present
invention include, but are not limited to, degradable polymers;
dehydrated salts; and/or mixtures of the two. As for degradable
polymers, a polymer is considered to be "degradable" herein if the
degradation is due to, in situ, a chemical and/or radical process
such as hydrolysis, or oxidation. The degradability of a polymer
depends at least in part on its backbone structure. For instance,
the presence of hydrolyzable and/or oxidizable linkages in the
backbone often yields a material that will degrade as described
herein. The rates at which such polymers degrade are dependent on
the type of repetitive unit, composition, sequence, length,
molecular geometry, molecular weight, morphology (e.g.,
crystallinity, size of spherulites, and orientation),
hydrophilicity, hydrophobicity, surface area, and additives. Also,
the environment to which the polymer is subjected may affect how it
degrades (e.g., temperature, presence of moisture, oxygen,
microorganisms, enzymes, pH, and the like).
[0034] Suitable examples of degradable polymers that may be used in
accordance with the present invention include polysaccharides such
as dextran or cellulose; chitins; chitosans; proteins;
poly(lactides); poly(glycolides); poly(E-caprolactones);
poly(hydroxybutyrates); poly(anhydrides); aliphatic or aromatic
polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene
oxides); and polyphosphazenes. Of these suitable polymers and
polyanhydrides may be preferred.
[0035] Dehydrated salts may be used in accordance with the present
invention as a degradable particulate. A dehydrated salt is
suitable for use in the present invention if it will degrade over
time as it hydrates. For example, a particulate solid anhydrous
borate material that degrades over time may be suitable. Specific
examples of particulate solid anhydrous borate materials that may
be used include, but are not limited to, anhydrous sodium
tetraborate (also known as anhydrous borax) and anhydrous boric
acid. Other examples include organic or inorganic salts like
acetate trihydrate.
[0036] Blends of certain degradable materials may also be suitable
for use as a degradable particulate. One example of a suitable
blend of materials is a mixture of poly(lactic acid) and sodium
borate where the mixing of an acid and base could result in a
neutral solution where this is desirable. Another example would
include a blend of poly(lactic acid) and boric oxide. Other
materials that undergo an irreversible degradation may also be
suitable, if the products of the degradation do not undesirably
interfere with either the conductivity of the fracture or
production of any of the fluids from the subterranean
formation.
[0037] In choosing the appropriate degradable material, one should
consider the degradation products that will result. These
degradation products should not adversely affect other operations
or components and may even be selected to improve the long-term
performance/conductivity of the propped fracture. The choice of
degradable material also can depend, at least in part, on the
conditions of the well (e.g., well bore temperature). For instance,
lactides have been found to be suitable for lower temperature
wells, including those within the range of 60.degree. F. to
150.degree. F., and polylactides have been found to be suitable for
well bore temperatures above this range. Also, poly(lactic acid)
may be suitable for higher temperature wells. Some stereoisomers of
poly(lactide) or mixtures of such stereoisomers may be suitable for
even higher temperature applications. Dehydrated salts may also be
suitable for higher temperature wells.
[0038] In some embodiments, a preferable result is achieved if the
degradable material degrades slowly over time as opposed to
instantaneously. The slow degradation of the degradable material,
in situ, helps to maintain the stability of the proppant
matrix.
[0039] In some embodiments of the present invention, degradable
particulates are included in the treatment fluids of the present
invention from about 5% to about 25% by weight of the proppant
particulates. In preferred embodiments, degradable particulates are
included in the treatment fluids of the present invention from
about 10% to about 20% by weight of the proppant particulates. One
of ordinary skill in the art with the benefit of this disclosure
will recognize an optimum concentration of degradable material that
provides desirable values in terms of enhanced conductivity or
permeability without undermining the stability of the high porosity
fracture itself.
[0040] In some embodiments, the methods of the present invention
provide a thermoplastic material and a degradable polyester
material (referred to collectively herein as "coating material")
that may be coated singly or in combination onto proppant
particulates so as to form proppant pillars. The coating material
may be capable of softening upon heating or upon encountering
temperatures present in a particular subterranean formation such
that the material may become tacky or adhesive and adhere and
envelope to the proppant pillars. Thus, the coating material may be
coated onto the proppant particulates so as to form proppant
pillars in situ within the subterranean formation itself. The
coating material is pliable such that it may twist and change
conformation as it encounters uniaxial or biaxial stresses, which
may enhance binding of the coating material to the proppant
particulates so as to form proppant pillars. The consolidating
agent used with the proppant particulates may also serve to
encourage adherence of the coating material onto the proppant
particulates so as to form proppant pillars. In some embodiments,
the coating material is preferably hydrophobic, such that
individual proppant pillars are isolated from other proppant
pillars within the treatment fluid. Such isolation may aid in
producing highly conductive channels within the fracture through
which produced fluids may flow.
[0041] The thermoplastic material for use in the present invention
may include any thermoplastic material suitable for use in a
subterranean formation capable of pliability upon reaching a
specific temperature. Suitable thermoplastic materials for use in
the treatment fluids of the present invention include, but are not
limited to, a polyolefin; a fluoropolymer; a polyimide; a
polyamide; a polyurethane; a polysulfone; a polycarbonate; a
polyacrylate; a polyacrylonitrile; a polyvinyl polymer; a
cellulose; any derivatives thereof; any copolymers thereof; and any
combinations thereof. Suitable polyolefins include, but are not
limited to, polyethylene; polypropylene; and polybutylene. In some
embodiments, the thermoplastic material is present in the treatment
fluids of the present invention from about 0.1% to about 20% by
weight of the proppant particulate. In preferred embodiments, the
thermoplastic material is present in the treatment fluids of the
present invention from about 1% to about 10% by weight of the
proppant particulate.
[0042] The thermoplastic material may be of any size and shape
suitable for use in a particular subterranean operation in
accordance with the methods of the present invention. The
thermoplastic material may be, for example, square-shaped;
rectangular-shaped; flake-shaped; ribbon-shaped; circle-shaped;
oval-shaped; triangle-shaped; cross-shaped; crescent-shaped;
diamond shaped; platelet-shaped; or bead-shaped. In some
embodiments, the thermoplastic material may be in the form of
nano-particles. In other embodiments, the thermoplastic material
used in the present invention may additionally be monolayered or
multilayered thermoplastic sheets. Multilayered sheets of
thermoplastic material for use in the present invention may include
two or more different types of thermoplastic materials in order to
vary the properties of the thermoplastic material or to enhance
individual thermoplastic properties. For example, a multilayered
thermoplastic material for use in the methods of the present
invention may comprise a more tacky thermoplastic material and a
readily pliable thermoplastic material such that adherence of the
multilayered thermoplastic material to the proppant particulates is
enhanced and a more stable proppant pillar is formed.
[0043] In some preferred embodiments, the thermoplastic material of
the present invention is in the form of a ribbon from about 2.5 to
about 250 .mu.m thick, from about 0.4 to about 6.5 mm wide, and
from about 5 to about 50 mm in length. In other preferred
embodiments, the thermoplastic material of the present invention is
in the form of a flake from about 2.5 to about 250 .mu.m thick with
a regular or irregular shape surface area in the range from about 2
to about 325 mm.sup.2. The size of the thermoplastic material
depends largely on its shape. One of ordinary skill in the art,
with the benefit of this disclosure, will recognize the shape and
size of the thermoplastic material to use in a particular
application.
[0044] The degradable polyester that may be used alone or in
combination with the thermoplastic material of the present
invention may be any polyester suitable for use in subterranean
operations, including natural and synthetic polyesters, as long as
the polyester is degradable. Suitable degradable polyester
materials include, but are not limited to, aliphatic polyester
homopolymers; aliphatic polyester copolymers; semi-aromatic
polyester copolymers; aromatic copolymers; telechelic polyester
oligomers; and any combinations thereof. Nonlimiting examples of
aliphatic polyester homopolymers include, but are not limited to,
polyglycolic acid; polylactic acid; and polycaprolactone.
Nonlimiting examples of aliphatic polyester copolymers include, but
are not limited to, polyethylene adipate and polyhydroxyalkanoate.
Nonlimiting examples of semi-aromatic polyester copolymers include,
but are not limited to, polyethylene terephthalate; polybutylene
terephthalate; polytrimethylene terephthalate; and polyethylene
naphthalate. A nonlimiting example of an aromatic copolymer
includes, but is not limited to, vectran. Nonlimiting examples of
telechelic oligomers include, but are not limited to,
polycaprolactone diol and polyethylene adipate diol.
[0045] The biodegradable polyester material may be of any size and
shape suitable for use in a particular subterranean operation in
accordance with the methods of the present invention. Like the
thermoplastic material of the present invention, the biodegradable
polyester material may be, for example, square-shaped;
rectangular-shaped; flake-shaped; ribbon-shaped; circle-shaped;
oval-shaped; triangle-shaped; cross-shaped; crescent-shaped;
diamond shaped; platelet-shaped; or bead-shaped. In some
embodiments, the biodegradable polyester material may be in the
form of nano-particles. In other embodiments, the biodegradable
polyester material used in the present invention may additionally
be monolayered or multilayered biodegradable polyester films.
Multilayered films of biodegradable polyester material for use in
the present invention may include two or more different types of
biodegradable polyester materials in order to vary the properties
of the biodegradable polyester material or to enhance individual
biodegradable polyester properties. For example, a multilayered
biodegradable polyester material for use in the methods of the
present invention may comprise a more tacky biodegradable polyester
material and a readily pliable biodegradable polyester material
such that adherence of the multilayered biodegradable polyester
material to the proppant particulates is enhanced and a more stable
proppant pillar is formed. In some embodiments, the biodegradable
polyester material is present in the treatment fluids of the
present invention from about 0.01% to about 20% by weight of the
proppant particulate. In preferred embodiments, the biodegradable
polyester material is present in the treatment fluids of the
present invention from about 1% to about 15% by weight of the
proppant particulate.
[0046] The degradable polyester material may further comprise a
plasticizer compatible with polyester. Suitable plasticizers may
include, but are not limited to, a polyethylene glycol; a
polyethylene oxide; an oligomeric lactic acid; a citrate ester
(e.g., a tributyl citrate oligomer, a triethyl citrate, an
acetyltributyl citrate, and an acetyltriethyl citrate); a glucose
monoester; a partially fatty acid ester; a polyethylene
monolaurate; a triacetin; a poly(.epsilon.-caprolactone); a
poly(hydroxybutyrate); a glycerin-1-benzoate-2,3-dilaurate; a
glycerin-2-benzoate-1,3-dilaurate; a bis(butyl diethylene
glycol)adipate; an ethylphthalylethyl glycolate; a glycerin
diacetate monocaprylate; a diacetyl monoacyl glycerol; a
polypropylene glycol; an epoxy derivative of a polypropylene
glycol; a poly(propylene glycol)dibenzoate; a dipropylene glycol
dibenzoate; a glycerol; an ethyl phthalyl ethyl glycolate; a
poly(ethylene adipate)distearate; a di-iso-butyl adipate; any
derivatives thereof; and any combinations thereof. The plasticizer
may aid in altering the glass transition temperature of the
degradable polyester material such that it becomes pliable at a
temperature different than if the degradable polyester material was
used alone. The glass transition temperature may be altered based
on the type and amount of plasticizer included in the treatment
fluid. In some embodiments, the plasticizer may be present in the
treatment fluids of the present invention having a degradable
polyester material in an amount from about 0.25% to about 40% by
weight of the degradable polyester material. In preferred
embodiments, the plasticizer may be present in the treatment fluids
of the present invention having a degradable polyester material in
an amount from about 1% to about 5% by weight of the degradable
polyester material.
[0047] The degradation of the biodegradable polyester materials of
the present invention may depend on, upon other factors, the
intrinsic property of the biodegradable polyester material (e.g.,
monomer structure, molecular weight, copolymer ratio,
crystallinity, shape, and the like), pH, or temperature. In some
embodiments, it may be preferable that the degradable polyester
material degrades before production of the well begins. In some
embodiments, it may be preferable that the biodegradable polyester
material degrade slowly over time. One of ordinary skill in the
art, with the benefit of this disclosure, will recognize the type
of biodegradable polyester material to use for a particular
application so as to achieve degradation in certain subterranean
environments.
[0048] A major advantage of using this method is that as the
biodegradable polyester material of the present invention degrades,
acid is released from the biodegradable polyester material. The
released acid may aid in or eliminate the need for filter cake
cleanup operations. Filter cake cleanup is often problematic
because operational constraints may preclude backflowing the well
to remove residual or unwanted filter cake. Thus, the biodegradable
polyester material may be used to clean the filter cake without
requiring an additional filter cake cleanup step or may reduce
amount of time and/or acid required to clean the filter cake.
[0049] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered, combined,
or modified and all such variations are considered within the scope
and spirit of the present invention. The invention illustratively
disclosed herein suitably may be practiced in the absence of any
element that is not specifically disclosed herein and/or any
optional element disclosed herein. While compositions and methods
are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps. All numbers and ranges disclosed
above may vary by some amount. Whenever a numerical range with a
lower limit and an upper limit is disclosed, any number and any
included range falling within the range is specifically disclosed.
In particular, every range of values (of the form, "from about a to
about b," or, equivalently, "from approximately a to b," or,
equivalently, "from approximately a-b") disclosed herein is to be
understood to set forth every number and range encompassed within
the broader range of values. Also, the terms in the claims have
their plain, ordinary meaning unless otherwise explicitly and
clearly defined by the patentee. Moreover, the indefinite articles
"a" or "an," as used in the claims, are defined herein to mean one
or more than one of the element that it introduces. If there is any
conflict in the usages of a word or term in this specification and
one or more patent or other documents that may be incorporated
herein by reference, the definitions that are consistent with this
specification should be adopted.
* * * * *